As many low sulfur natural gas fields are being depleted, natural gas production from sour gas fields has become increasingly necessary to meet current energy demands. However, acid gas removal from sour gas fields, and especially from highly sour gas fields (e.g., acid gases at or above 10 mol % CO2 and at or above 0.5 mol % H2S) typically requires significant capital investment and operating costs. Moreover, gas production facilities face the challenge of increasing acid gas content during production, especially where CO2 is re-injected into the formation.
For example, acid gases can be removed by conventional amine processes, however, such processes are often not economical due to the need for ever increasing amine circulation at increasing acid gas content in the feed gas, which requires higher steam heating duty in the solvent regeneration, leading to increased greenhouse gas emissions. Moreover, chemical solvents have an upper limit in their acid gas loading capacity (i.e., mole of acid gas per mole of amine), which is inherently dictated by the chemical equilibrium between amine and the acid gases. On the other hand, physical solvents operate on the principal of Henry's law. Thus, acid gas loading of the solvent actually increases with the acid gas content of the feed gas, making physical solvents a desirable choice for highly sour gas fields. Moreover, the solvent regeneration processes for physical solvents are also often less problematic as these solvents can be regenerated to some extent by flash regeneration, which eliminates the need of heating, which in turn minimizes greenhouse gas emissions.
However, flash regeneration of physical solvents without external heating can only partially regenerate the solvent and is in most cases not suitable to treat highly sour gases to meet pipeline gas specifications (e.g., 1 mol % CO2 and 4 ppmv or lower H2S). These issues are exacerbated when the feed gas to be treated contains significant amounts of hydrocarbons as the physical solvent tends to absorb most of the hydrocarbons, resulting in higher hydrocarbon contents in the CO2 stream and a lower heat content in the treated gas stream.
One exemplary configuration and methods of acid gas removal using physical solvent is described in our copending International application PCT/US09/58955 where acid gas is removed at high pressure with a lean physical solvent, and where the rich solvent is heated (e.g., using waste heat from compressor discharge and lean solvent) and subjected to flash regeneration to so regenerate the lean solvent. Such approach advantageously reduces heat requirements for regeneration; however, it is in most cases only suitable for feed gases with relatively low H2S content where treated gas must conform to pipeline specification. In other known exemplary configuration and methods, CO2 is absorbed in a physical solvent at high pressure as described in WO 2005/035101A1. Here, the lean solvent is regenerated via flashing and dual stripping where carbon dioxide in an atmospheric flash vapor strips the H2S from the rich solvent, while sweet gas strips the carbon dioxide from the solvent in the stripper. Despite the significant advantages using such system, such methods and configurations are once more limited to feed gases with relatively low (about 90 ppmv) H2S content. Similarly, U.S. Pat. No. 7,192,468 discloses methods and configurations in which CO2 is absorbed at high pressure to form a rich solvent that is then regenerated over multiple flash stages and a stripping column using a H2S free gas. However, such configuration recovers the stripper overhead as fuel gas, which may require further treating, and is generally not desirable in facilities with excess fuel gas supply.
In yet further known configurations and methods of acid gas removal, the solvent is regenerated over multiple flashing stages as described in U.S. Pat. No. 7,637,987. Here, the flashed solvent is then stripped in a stripper using the recycle gas from the flash stages and fed to an absorber that is operated with an isothermal gradient or with a decreasing top-to-bottom thermal gradient. While such configurations and methods provide several significant advantages over other known systems, various disadvantages nevertheless remain. Among other things, when recycled gas is employed as stripping gas, the flow rate is limited by the CO2 that can be flashed off in the high pressure stage, which may not be sufficient to fully regenerate the solvent when used to treat a high H2S content feed gas.
Thus, although various configurations and methods are known to remove acid gases from a feed gas, all or almost all of them suffer from one or more disadvantages. Among other things, and especially where H2S levels in feed gas is relatively high, use of physical solvent without heat application is typically not suitable to produce a treated gas that meets gas pipeline specifications. Therefore, there is still a need to provide improved methods and configurations for acid gas removal.